Phased investment for H2S removal

Awareness of H2S removal process steps and how they can be combined to reduce costs compared to the use of a single sweetening unit operation

Jim Abbott and Vince A Row
Johnson Matthey Catalysts

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Article Summary

Detailed definition of gas processing projects is often difficult because of uncertainties in the composition of feedstocks from new fields and in future requirements. Understandably, this has led to process plants being robust but, in hindsight, over-designed and unnecessarily expensive. To avoid this, the benefits of a modular approach to both process design and phasing investment should be considered. For example, to meet stringent product specifications with varied (or varying) feedstocks, a single sweetening process may not be the most cost-effective or even an acceptable option.

This drives designers, licensors and vendors to minimise equipment and projected operating costs at the design stage. Combining roughing (bulk sulphur removal processes) with polishing (removal of ppmv sulphur levels) has several economic and reliability advantages. Another way to minimise costs is via a phased investment approach to project implementation, so that capital is spent only when required. Through realistic assessment of the project development and the inclusion of appropriate civil work and tie-ins, investment can be delayed, cash flow improved and, in some instances, unnecessary capital expenditure avoided. Operators may also be able to take advantage of ongoing process and product improvements.

Integration of sweetening processes

One of the most widely used sweetening systems is the regenerable wash system. A number of different wash solutions can be utilised. For example, various amines, potassium carbonate and refrigerated methanol and different designs can be configured for the bulk removal of H2S, CO2 or both. These wash systems are cost-effective for the rough sweetening duty, but a number of disadvantages need to be borne in mind at the design stage:
— Costs increase greatly when wash systems are used for H2S polishing
— Operating upsets can put the product natural gas out of specification. Reliability is important
— It may be costly to design the system to cope with every possible feed gas variation.

Transmission natural gas pipeline specifications for H2S are typically around 4.0 ppmv maximum. However, in some sweetening applications, lower H2S specifications (0.5–1.0 ppmv) are required for other downstream processing reasons. To guarantee meeting an operating H2S specification, a wash system is often over-designed, incurring greater capital expense.

When an amine wash solution system is used for sweetening in the polishing range the costs escalate, as the product H2S specification becomes tighter. The typical relationship is shown in Figure 1.

To achieve very low H2S levels, the regenerated wash solution, which is pumped to the top of the absorber, must contain very low H2S levels. This requires a higher reboil heat load and more stages in the regenerator column, pushing up capital and operating costs rapidly.

Fixed-bed polishing uses highly reactive absorbents to react chemically and therefore irreversibly remove low levels of contaminants from gas and liquids. Johnson Matthey produces the Puraspec range of absorbents for different duties. In the context of natural gas sweetening, the absorbents have a high capacity for complete H2S removal down to very low levels (<0.1 ppmv) at ambient temperatures. This is cost-effective for inlet levels of H2S ranging from 1–100 ppmv, depending on the gas flow rate. No services, such as steam or cooling water, are required, and there is no waste or purge hydrocarbon stream needing further processing (using Redox, Claus or incineration). The spent absorbent can simply be recycled through a metal reprocessing plant. By combining a wash system and fixed-bed polishing in series, as shown in Figure 2, a cheaper total process solution can be found.

Figure 3 shows an example of the annualised cost for a combined system, which is designed for a final H2S specification of <1.0 ppmv. The cost is dependent on the design H2S level in the gas, leaving the wash absorber and flowing to the fixed bed. The minimum cost at around 4–8 ppmv is where the fixed-bed size and absorbent consumption costs balance the extra wash system costs.

Two other beneficial features result from this combined configuration. First, it gives much more flexibility to cope with design scenarios with different gas compositions (e.g. from different fields). This may be the case when widely varying levels of H2S and CO2 are anticipated. Second, and perhaps most importantly, the fixed-bed absorber provides ultimate assurance of final gas purity. It is becoming more common for gas contracts to severely penalise failure to sweeten gas properly, either in terms of penalty payments or even by refusal to accept the off-specification gas, which would probably have to be flared. In these situations, operating upsets in wash systems can be very costly in a short period of time. This aspect alone can justify the inclusion of a fixed-bed absorber downstream, which will simply mop up any H2S breakthrough from such an incident.

Membrane sweetening systems can also be favourably integrated with fixed-bed polishing. In natural gas treating, membranes can be used to separate CO2 and H2S from hydrocarbons in one or two stages. Relative to wash systems, the economics of using membranes generally become more favourable for greater levels of CO2 removal. Another advantage is that water is removed to give a product stream, which is essentially dry, in a single processing step. However, there is little that can be done in any given situation to vary the relative quantities of CO2 and H2S removed by permeation through the membrane. For instance, if significant extra CO2 must be extracted to meet the final H2S specification, this can be costly both in terms of provision of extra membrane modules and hydrocarbon losses. This is, again, where a series configuration of membranes followed by fixed-bed polishing can pay off. As the gas is dry, it is important to use a chemical absorbent, which functions effectively in the absence of water vapour. The following case studies illustrate the integration of sweetening unit operations.

Case study 1: Installation of fixed-bed backup to wash system
Gas from a new field is to be processed through an offshore platform by a North Sea gas producer. The gas is sour and is to be sweetened offshore using an amine wash system to give a satisfactorily low H2S level (<1.0 ppmv) before pipeline transmission to the onshore terminal.

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